Not Applicable.
The present invention relates to apparatus and methods for a subsea tie back and more particularly to a pipe disposed within the flowline for conducting flowline operations and still more particularly to methods for treating a flowline utilizing the inner pipe.
Subsea tie backs are flowlines tying back the trees of producing wells in producing field to a processing facility. The production facility processes the well fluids received through the producing well flowlines by separating the gas from the oil and by removing unwanted constituents such as gas and water, which at low temperatures and pressures, form undesirable hydrates. The conditioned and stabilized oil is either pumped through an export pipeline or transported by tanker. Typically there is a separate gas line for the produced gas.
Referring now to FIG. 1, there is shown a typical tie back system that includes a production facility 10 on an offshore platform 11 with two insulated tie back flowlines 12, 14 extending to a subsea manifold 16. The manifold 16 is many miles from the production facility 10. There are a plurality of christmas trees 18 in an oil field 20 having individual flowlines 21 extending from each tree 18 to manifold 16 where the production from each well is commingled. Electrical and hydraulic control umbilicals 22, 24, respectively, extend from platform 11 to manifold 16 to control the operation of manifold 16. Particularly, the control umbilicals control valves on manifold 16 and trees 18 as well as the chokes (not shown) in the individual christmas trees 18. A chemical injection line 26 also extends from the platform 11 to the manifold 16 and communicates with the flowlines 12, 14 for chemical treatment in the flowlines 12,14 and in the wells.
The production from each of the trees 18 passes to the manifold 16 and then is commingled for passage through the dual flowlines 12, 14 to the production facility 10 on platform 11. The production from field 20, of course, is raw production well fluids. The production facility 10 processes the crude produced by the trees 18 by removing, as for example, any water and gas in the well fluids such that only oil remains to be exported by an export pipeline 28 to shore. Instead of an export pipeline, a floating production, storage and offtake (FPSO) vessel may be used which not only process the well fluids but also stores the oil and gas for off loading. The production needs to be stabilized before it is exported either through the export pipeline 28 or the export vessel. To stabilize the crude means to place the oil in condition to put it in the export pipeline 28 and pump it a great distance. Although only field 20 is shown in FIG. 1, production facility 10 may also receive the production from other surrounding fields, such as oil fields 30, 32.
Although FIG. 1 shows the platform 11 supported by the sea floor 34, production now is occurring in deep water. Deep water is typically where the water depth is over 1,000 meters. In 1,000 meters of water, the production facility 10 would be on a floating platform anchored to the ocean floor or on a vessel. In deep water, the production facility 10 must be a floating facility such as a SPAR, a TLP (Tension Leg Platform) or an FPSO.
Using subsea flowlines to tieback subsea wells to a remote processing facility is an established method for developing oil and gas fields. The design and specifications of the subsea flowlines is driven by the needs of flow assurance management. Flow assurance management includes ensuring that the unprocessed well fluids: (1) are able to reach the process facility; (2) arrive at the process facility above critical temperatures (such as the wax appearance temperature or cloud point and the hydrate creation temperature); (3) can be made to flow again after planned or unplanned shutdown (particularly with respect to clearing hydrate blockages); (4) avoid hydrates, wax, asphaltene, scale, sand, and other undesirable contents from building up in the flowline; and (5) can be made to flow at a range of driving pressures, flowrates, and compositions. See xe2x80x9cEmergence of Flow Assurance as a Technical Discipline Specific to Deepwater Technical Challenges and Integration into Subsea Systems Engineeringxe2x80x9d by Kaczmarski and Lorimer of Shell, OTC 13123 Apr. 3, 2001.
The typical methods used to achieve the many different demands of flow assurance include using highly insulated flowlines, pipe-in-pipe flowlines, active heating of flowlines, and dual flowlines. These approaches have a high cost, however. The oil industry therefore is continually attempting to increase tieback distances and to reduce costs. The challenge is to have longer tieback distances while at the same time achieving acceptable costs. This is proving difficult for the industry, especially because subsea tiebacks tend to be the approach used for the smaller reservoirs (which demand lower costs.) Deeper water exacerbates the difficulties of subsea tie backs with the added disadvantage that it is much easier for hydrates that can block the flowlines to form in deep water. See xe2x80x9cThe Challenges of Deepwater Flow Assurance: One Company""s Perspectivexe2x80x9d by Walker and McMullen of BP, OTC 13075 dated Apr. 30, 2001.
Wax in the well fluids builds up on the inner surface of the flowline over time unless the temperature of the well fluids is maintained above the wax appearance temperature, i.e. the cloud point where particles appear in the liquid turning the liquid cloudy. The wax appearance temperature varies between 50 and 120xc2x0 F. depending upon well fluid properties. It is important that the well fluids maintain a high temperature, i.e. are hot, as they pass through the flowline from the manifold 16 to prevent the wax from plating up the flowline. However, sometimes the cooler temperatures can not be avoided. For example, the well fluids adjacent the wall of the flowline are cooler than the bulk of the fluid passing through the central portion of the flowline. Thus, the wax will tend to plate up on the inner surface of the flowline where the temperatures are cooler, i.e., below the wax appearance temperature. Other undesirable constituents of the well fluids, such as asphaltene, scale, and sand, also tend to build up in the flowline.
A subsea tie back preferably provides for the use of a pig to be pumped through the flowline to remove the wax, asphaltene, scale, sand and other constituents in the well fluids that tend to build up in the flowline. xe2x80x9cPigxe2x80x9d stands for pipeline inspection gauge. Dual flowlines with an end-to-end loop are preferred to provide a full circuit for the pig so that the pig can pass through the flowline from the production platform, through the tie back flowline, and then back to the production platform. Scraper pigs run through the flowline to remove wax and other build up on the inside of the flowline and are run at a frequency depending upon the fluids and other conditions.
Intelligent pigs can also be used to inspect the inside of a flowline. In most typical intelligent pigging, the pig flows through the flowline and the information gathered by the pig is discerned after the pig has passed through the flowline. If all the necessary information has not been gathered, then it is necessary to run the pig back through the flowline, particularly over a certain area of the flowline which is of concern. It would be preferred to have a system that provides xe2x80x9creal timexe2x80x9d information as the pig passes through the flowline. Real time information allows the operator to see the information gathered by the pig in real time as the pig passes through the flowline. This permits the operator to also control the inspection tools that are carried with or are part of the intelligent pig.
The undesirable constituents of the well fluids, such as wax, asphaltene, scale, and sand, may also be prevented or removed with chemicals. Chemicals may be injected continuously into the flowlines 12, 14 through chemical injection line 26. The chemicals condition the well fluids to prevent the formation of wax on the walls of the flowlines 12, 14. Continuous injection of chemicals, however, is a huge expense.
A problem during shut in of production is that the well fluids themselves become gel-like, i.e. very viscous, when the well fluids reach their pour point temperature. Thus, if the well fluids dip below the pour point temperature, they become very viscous and it may be difficult to restart flow.
Another problem, particularly when flow through the flowlines in shut down, is the formation of hydrates. Hydrates are a solid form of a mixture of the gas and water in the well fluids at a certain temperature and pressure. Hydrates can be produced from methane, carbon dioxide, nitrogen, or other gas with water in the well fluids to form a crystalline structure. Hydrates form instantly into a solid to block and close the flowline to flow. For example, if there is an unexpected shut in, the well fluids in the flowlines begin to cool down. After a cooling down period, the well fluids then go into the hydrate region of temperature and pressure. The gas may collect at the high points in the flowline and the water may collect at the low points in the flowline. However, once flow is started again the gas and water mix to instantly form hydrates and block the flowline.
Hydrate chemistry is very complex. It becomes even more complex because of all the different types of fluids being produced in the well fluids. Thus, it is difficult to know exactly what kind of hydrates will form and how they will form. Further, because it occurs in a subsea pipeline, it is difficult to know exactly how the hydrates form and what causes them to form. The chemistry is much simpler if the fluids are just water and gas, but when the fluids also include oil and other chemicals such as salts, the hydrate chemistry becomes very complex. The mechanisms of hydrate formation in liquids makes it complex, particularly when hydrates can be formed with gas in the liquid oil. Hydrate problems in pipelines are well known in the industry.
Although the system is designed for normal operation, there may be an unexpected or unplanned event that requires production to be shut in and flow through the flowline stopped. No matter how much or what kind of insulation has been used around the flowline, once flow stops, eventually the well fluids in the flowline will reach the same temperature as the surrounding sea water, typically 40 to 50xc2x0 F. Thus, the temperature of the well fluids drops under the wax appearance temperature and hydrate formation temperature.
Thus, it is important to take steps to keep the temperature of the well fluids above the hydrate appearance temperature as well as above the wax appearance temperature. One method of maintaining the temperature of the hot produced well fluids is to insulate the flowlines. For example, the flowline may be disposed within a larger diameter pipe to form dual concentric pipe. Insulation is disposed in the annular area between the inner flowline and outer pipe. Alternatively, heated fluid may be flowed through the annulus of the dual concentric pipe to heat the well fluids flowing through the inner flowline. However, even if the annulus is insulated, there is loss of heat to the sea water environment around the outer pipe. Although loss of heat may be reduced if the dual concentric pipe is buried in the sea floor, there will still be a loss of heat through the outer pipe into the subsea floor.
Dual concentric pipe is very expensive to lay and install on the ocean floor. This expense is even greater in laying such large pipe in deep water. The size and cost of the vessel to lay such pipe is extremely expensive and only a few vessels are available which can handle such large pipe.
Another method of maintaining the temperature of the well fluids is to heat the well fluids as they flow through the flowline. There are a number of methods to active heating of flowlines where an inner flowline is disposed within an outer pipe. One approach is to flow hot liquid, such as water, through the annular area between the flowline and outer pipe. Flow through the annular area may be continuous or it may be used only in a contingency. For example, hot liquid may be flowed after a shut down to heat the inner flowline and well fluids and to restart flow through the flowline. Another approach is to use a bundle of flowlines disposed in a large carrier pipe that might be 40 inches in diameter. One of the inner flowlines may carry hot fluids such as hot water. The bundle of pipes may also be insulated inside the carrier pipe. This pipe bundle is built on shore and then towed off shore for installation. A still another approach is the use of electric heating of flowlines. Electric heating is disposed between the inner flowline and outer pipe and is then used in case of a contingency.
Although a pipe carrying hot liquids disposed inside an outer pipe is known to have preferred thermodynamic properties, installing an smaller pipe inside an outer pipe is time consuming and expensive. One method is to install the inner pipe within the outer pipe as sections of the outer pipe are being connected for assembly, although such an assembly and installation would be very expensive.
Also, pigging is a normal requirement for flowlines and a pig cannot be pumped through the flowline if there is an obstruction within the flowline such as an inner pipe. A pig is a solid object that passes through the flowline when pushed by the flow of fluid in the flowline. Thus, all flowlines are typically designed so that they can be pigged, this being a normal design parameter. Still further, a pipe inside the flowline raises a serious corrosion issue since an inner pipe creates stagnant areas inside the flowline causing serious corrosion sites due to water and debris collecting and forming strong electrolytes and creating galvanic cells. Thus, no one has considered placing something inside the flowline for flow assurance because that would interfere with the passage of a pig through the flowline. Thus, putting an inner pipe inside the flowline is a complete anathema to present flowline design because something inside the flowline means it cannot be pigged.
To mitigate against an unplanned shut down, chemicals, such as methanol, are flowed from the production facility 10, through the chemical injection line 26, and into the flowlines 12, 14 to commingle with the well fluids in an attempt to prevent the well fluids from forming hydrates. The volume of methanol required is a function of the percentage of water in the well fluids. As the percentage of water in the flow increases over the life of the well, the volume of methanol required eventually becomes so large as to be impractical and too expensive.
Flowlines are designed to ensure that flow is never blocked in the flowline. This is because the only solution to a blocked flowline is to replace the flowline completely. A design that ensures that there is never any blockage in the flowline is very expensive, however. For example, having inner and outer pipes laid by expensive vessels adds a substantial cost to install the flowlines. Chemical injection must also be available and installed for the flowline. Thus, the system must be designed for an unexpected shut down so as to ensure against blockage of flow at that time and avoid the expense of a new flowline.
The amount of production through the flowlines also varies over the life of the producing field. It takes many years to complete and produce all the wells in a field and thus a different number of wells may come on line at different times. This causes a variance in the amount of well fluids being produced. The flowlines must be installed early on after the initial wells are producing. Thus, the flow of the well fluids through the flowlines changes over time. For example, the amount of flow and the pressure of the produced fluids changes, the amount of water in the well fluids changes, and the amount of gas changes. Thus, over the life of the well, there is a large a range of flows and compositions of well fluids through the flowlines. These changes must be coped with by the flowlines.
Still another problem encountered in existing systems is that the flowlines are designed to be full of well fluids flowing to the process facility. However, the driving pressure of the well fluids and the flow rate of the well fluids may vary as well as the composition of the well fluids. The term xe2x80x9cdriving pressuresxe2x80x9d relates to the turn down of production and thus flow through the flowlines. The variation in flow rate also causes a variation in the temperature of the well fluids. There are chokes in the trees 18 that control the amount of well fluids being produced in each of the wells to control the production from the reservoir in field 20. The manifold 16 may be mixing different well fluids being produced from different reservoirs where the composition of the well fluids in the reservoir may be different. These are all controlled in an attempt to maximize production.
However, the flowlines have a certain size and a certain hydraulic capability. Thus, although the flowlines will be full of fluid, the flow rates and driving pressures will vary and the constituents of the well fluids will vary. The driving pressures and flow rates are related and the arrival temperature of the fluids at the production facility is also related. The industry standard program for analyzing the flow through the flowlines is called xe2x80x9cOLGAxe2x80x9d. This is used to analyze the flow through the flowline to achieve the proper flowline design.
The two flowlines 12, 14, shown in FIG. 1, are xe2x80x9cdual flowlinesxe2x80x9d because they are basically side by side. Dual flowlines allow the operator to change the amount of flow from the manifold 16 to the production facility 10 by shutting down one of the flowlines. It also provides a broader range of flow rates, pressures, and temperatures. By closing one of the lines down, the cross-sectional flow area is changed. Because production from a field deteriorates over time, ultimately, only one of the two flowlines may be used for transporting the well fluids from the manifold 16 to the production facility 10. This is called xe2x80x9cturn downxe2x80x9d. The two lines provide more flexibility in the management of the flow and also allow xe2x80x9cturn-downxe2x80x9d as needed. Also, one of the flowlines may be a back-up, such that if one of the flowlines is blocked, the other flowline is still available for production.
Dual flowlines also allow round trip pigging. The two flowlines 12, 14 include valves at the manifold 16 so that production can be shut off in a particular flowline 12, 14 and a pig sent through the line beginning at the platform 11 to travel from the platform 11 to the manifold 16. The pig then returns through the other producing flowline to platform 11.
As production of the field matures, the production of the field depletes such that the processing facility is no longer fully utilized. It is preferred to use the spare capacity of the processing facility and thus, it is desirable to tie back the processing facility with other producing fields so that the processing facility is fully utilized. These other fields may be many miles away from the processing facility. Thus, there is the need for subsea tie back flowlines to extend many miles across the ocean floor to reach various producing fields around the processing facility and process a plurality of producing fields. It is cheaper to use existing process facilities and use subsea tie backs than to build new production facilities.
One objective is to be able to build subsea tie back flowlines that are up to 100 miles long. The ultimate objective is to have the production facility onshore with tie back flowlines extending from shore out to the subsea manifolds. Thus, one production facility could process production from all fields within 100 mile radius. This would provide substantial cost savings in deep water production.
The present invention overcomes the deficiencies of the prior art.
The methods and apparatus of the present invention include an inner pipe disposed within an outer pipe for the purpose of assuring flow through the outer pipe. The inner pipe may extend partially or completely through the outer pipe and may be installed into the outer pipe at any point along the length of the outer pipe. Further, the inner pipe may be installed into the outer pipe without regard to whether there are fluids passing through the outer pipe. It also should be appreciated that more than one inner pipe may be disposed within the outer pipe.
The inner pipe may be either a jointed pipe or preferably a continuous pipe. The inner pipe plus its contents are nearly neutrally buoyant or fully neutrally buoyant such that when in the fluids of the outer pipe, the inner pipe plus its contents have substantially the same density as the fluids in the outer pipe. This substantially neutrally buoyancy allows the inner pipe to minimize friction against the outer pipe upon inserting and installing the inner pipe within the outer pipe and allows the inner pipe to be installed at great distances within the outer pipe. The fluids used during installation are selected to achieve neutral buoyancy. Once installed, the fluids within the pipes can be changed from the fluids used during installation to the fluids used during production operations. During production operations, however, it is not necessary for the inner pipe to be substantially neutrally buoyant.
The jointed pipe may be either a metal or composite tube having segments connected together and installed using snubbing techniques. The continuous inner pipe is either a metal or composite coiled tubing. If metal coiled tubing, the metal coiled tubing is made substantially neutrally buoyant with selected fluids inside and out. If a composite coiled tubing, the composite coiled tubing is engineered for the required mechanical properties required for flow assurance within the outer pipe and particularly is engineered to be substantially neutrally buoyant with selected fluids inside and out. In a most preferred composite coiled tubing, conductors and fiber optic cables are embedded in the wall of the composite coiled tubing to provide power and communication through the wall of the coiled tubing. Electrical conductors may be used to power a tool attached to the end of the inner pipe and the communication conductors may be used to monitor temperature and pressure along the length of the inner pipe. Further, the conductors may be used to transmit signals and data through the wall of the pipe either from a tool or other assembly connected to the end of the inner pipe. The coiled tubing may be installed using coiled tubing techniques and inserted and installed at any point along the outer pipe such as through connection points in the outer pipe.
Several motive means may be used individually or in combination to install the inner pipe within the outer pipe. The hydrodynamics of the flow of fluids in the outer pipe may be used to move the inner pipe in the same direction as the flow of fluids. Alternatively, a flow restriction member, such as a pig, may be attached to the end of the inner pipe to create a pressure differential for moving the inner pipe within the outer pipe. In a preferred embodiment, a propulsion system that engages the outer pipe is used to move the inner pipe through the outer pipe. The propulsion system may be either electrically or hydraulically powered. If hydraulically powered and installed over great distances, gas slugs may be passed through the inner pipe to maintain sufficient energy for driving the hydraulically powered propulsion system. The propulsion system may have a segmented housing allowing the propulsion system to pass through bends in the outer pipe.
The inner pipe may be anchored within the outer pipe such as by a latch mechanism or a friction coupling where the inner pipe frictionally engages the outer pipe.
The inner pipe may be used in various types of circuits. In an open circuit, one end of the inner pipe is open to the fluids flowing through the outer pipe such that the fluids passing through the inner pipe may mix and commingle with the fluids in the outer pipe. In one embodiment of a closed circuit, the end of the inner pipe communicates with the environment outside the outer pipe whereby the fluids flowing through the inner pipe do not mix and commingle with the fluids in the outer pipe and are allowed to flow through the inner pipe and into the environment around the outer pipe. In another embodiment of the closed circuit, the end of the inner pipe may communicate with a return line exterior to the outer pipe. In still another embodiment of the closed circuit, a pair of inner pipes communicating through a connection at their free end are disposed with the outer pipe allowing fluids to flow through one inner pipe and then return through the other inner pipe.
In one method of the present invention, hot liquids are pumped through the inner pipe to control the temperature of the fluids flowing through the outer pipe. In an open circuit, the fluids pumped through the inner pipe are compatible with the fluids in the outer pipe so that they may be mixed and commingled. In a closed circuit, the liquids passing through the inner pipe are compatible with the environment around the outer pipe. In still another closed circuit, the hot fluids may be any available fluids that can be circulated through an inner pipe and a return pipe.
In another method of the present invention, liquids with different densities may be passed through the inner pipe causing the inner pipe to move up and down inside the outer pipe, thereby stirring up any stagnate fluid areas. The inner pipe may also be reciprocated within the outer pipe to stir up any stagnate fluid areas.
In another method of the present invention, in an open circuit, chemicals may be pumped through the inner pipe to mix with the fluids in the outer pipe so as to condition the fluids in the outer pipe. In another embodiment using a closed circuit, the inner pipe may include a series of valves that may be selectively opened to allow liquids inside the inner pipe to mix with fluids in the outer pipe at one or more locations along the outer pipe.
In another method of the present invention, a tool may be attached to the end of the inner pipe to clean the interior of the outer pipe.
In another method of the present invention, the inner pipe may be used to depressurize the fluids in the outer pipe to prevent the formation of a blockage due to undesirable components of the well fluids solidifying within the outer pipe.
In another method of the present invention, the inner pipes may be used in an open circuit to mix chemicals with the fluids in the outer pipe to allow the fluids in the outer pipe to be pumped after flow has been stopped.
In another method of the present invention, a pair of inner pipes may be disposed within the outer pipe with one of the pipes passing fluids at high velocity therethrough and with the other pipe being a return pipe pumping undesirable contaminates, such as sand, in the fluids from the outer pipe.
In still another embodiment of the present invention, an inspection tool may be disposed on the end of the inner pipe and connected to conductors in the walls of the inner pipe such that a real time internal inspection may be conducted of the outer pipe.
In still another embodiment of the present invention, a first inner pipe may be disposed within a non-bonded flexible outer pipe to prevent compression of the outer flexible pipe. The first inner pipe may include a flexible gooseneck on the end thereof to negotiate any bends. A second inner pipe may then be inserted inside the first inner pipe and further extended through the flexible gooseneck such that the second inner pipe may be inserted into a flowline connected to the nonbonded flexible outer pipe.
In still a further method of the present invention, the inner pipe may be used to transport the fluids in the outer pipe should flow through the outer pipe be reduced. Further, the inner pipe may be substituted with another inner pipe having either a smaller or larger diameter to adjust the flow area either through the inner pipe or through the annulus formed between the inner pipe and the outer pipe.
The methods and apparatus of the present invention are particularly applicable to subsea tie backs with the inner pipe being used for a variety of flow assurance operations to ensure flow through a flowline. In particular, the inner pipe may be used to either avoid or remove hydrates, wax, asphatene, scale, sand, or other desirable constituents of the well fluids flowing through the flowline.